Ladies and gentlemen, welcome to the Tethys Oil Q3 earnings reports 2021. Throughout the call, all participants will be in listen only mode, and afterwards, there will be a question and answer session. Today, I am pleased to present Magnus Nordin, Managing Director, and Petter Hjertstedt, CFO. Please begin your meeting. Thank you very much. Good morning, all. Welcome to the November 2021 earnings call with Tethys Oil, where we will discuss the third quarter 2021. As you can see from our first slide here with our highlights, it's been rather a good quarter. Production hanging in well above 11,000 barrels of oil per day with an oil price that has been climbing throughout the year. For the third quarter, we achieved a sales price of $66.70. As you know, prices have steadily climbed. For the fourth quarter, we would certainly expect to have prices considerably higher than the $66 of the third quarter. More importantly, maybe, quarter three saw massive cash generation. With $13 million worth of free cash from our assets, it's one of the stronger quarters we have seen in recent memory. That has impacted our net cash position, which already this time of year, by the end of September, stands at close to $60 million, which will present our board with an agreeable discussion on what to do with this cash as we move into next year. That's, of course, something that we would be delighted to get back to you on in a couple of months' time. Maybe not surprisingly, we have the strongest quarter since the start of the pandemic. Much of course to do with oil prices, but also with a robust strong asset in the bottom Blocks 3 and 4 with good cost control and a stable and proficient production. On the exploration side we've seen a lot of activity in particular on our exploration Blocks 56 and 58 where we are now moving up to see an interesting work program. In Block 56 we expect to start within the next couple of months a 3-well exploration and appraisal program on the Al Jumd trend the northern part of the block where we will target combined prospective resources of some seven million barrels. This is in the small sliver of the block. There will be much more detail later in the call on the exploration upside and then the exploration plans for Block 56. We are downgrading the full year production a little bit. We are now looking at coming in at some 11,100 barrels of oil per day, which is down a little bit from what we expected at our August call. Mainly what we are seeing is a backlog of workovers and a backlog of ongoing surface maintenance. As we move back into a normal operating environment, we will soon be back in full rotation on crews. As we've also been able to open up more wells for production, the need for workovers has become more obvious and we have a backlog of renovating wells and, as we open up more wells, also work these over. This is something we are confident will be rectified over time. For the fourth quarter, we will be a little bit weaker on production than we originally had for. Turning to production, as you can see, as we enter the pandemic, we were around above 13,000 barrels of oil per day. With the pandemic setting on, we dropped down to just below 11,000, stayed there for a couple of quarters, came back up above 11,000 and started the year on our way up towards 12,000. We had to go a little bit easier in the second quarter. As the third quarter moved on and into the fourth quarter, we saw an increased need for workovers. We had some delays in getting back to full rig capacity. We are now running at three rigs for the drilling and a fully employed workover rig. The fourth quarter will be a little bit weaker than expected. Stay tuned for our monthly updates and of course our guidance for next year as we move into 2022. Let's have a quick look at the oil price. This is rather interesting slide that we see here, and that's how demand for oil has actually developed over the year 2000. As you see, we started the millennium at below 80 million barrels of oil consumption a day. Before the pandemic, we were up to close to 100 million barrels a day. This is of course quite a high number. For the oil industry to sustain this, when we are now roaring back at the speed we are, dropping down to 90, which actually what is not worse than dropping down to 2013, 2000 levels during the 2020 year. We came back to 96 million in 2021 and are currently looking at more than 100 million barrels, i.e. record oil demand, after the pandemic. The main take here I think is that, notwithstanding the need to move into other sources of fuel than fossil fuels, the trend of increased use of oil, not necessarily other fossil fuels, but oil, is still unbroken. With the underinvestment we have seen since the onset of 2020, we would expect the next year and couple of years to still see a need for a rather buoyant oil price to simply meet the demand that we have. Turning to the next slide, which is a little bit more detailed. We clearly see no downward pressure on oil price in 2021. The OPEC+ maintenance of production increases seems to be very well managed and quite predictable. The uncertainties as we will move into next year is partly over U.S. shale, where we have seen an admirable fiscal discipline from the U.S. shale companies, where cash flow is, I think for the first time in U.S. shale history, actually, held higher than increased production, which has helped of course to stabilize the market. The interminable discussion of Iran, will Iran production be allowed back? In that case, when and under what circumstances? For 2022, we believe that we will continue to have a strong and well-managed oil price. We will not expect any major surprises on the upside. If there would be any surprises, that would primarily be on the downside. Given that we are actually below average storage and inventory at this time, we would be quite optimistic for a continued strong and buoyant oil price also for 2022. On that note, let us take a little bit of a look at our own oil price development, how it has developed over the year and taking into account also that we have a two-month lag in our sales price. I will turn to a detailed discussion from our CFO, Petter, who, I'm sure will be able to explain the intricacies of our official selling price calculations. Petter, please. Thank you, Magnus. Yes, let's start the financial discussion with a look at the pricing that forms the basis of our income. The official selling price for the Omani Blend, which is the crude quality that Tethys Oil produces, is set through a mechanism whereby there is a monthly average price based on the front month contract as traded on the DME exchange in Dubai. In fact, the so-called spot contract over a course of a month forms the basis of the selling price two months thereafter. This should be familiar to most of you, but it's worth reminding you. As you can see in the graph, for instance, if we look at the average price for October, which was just above $81 per barrel, that forms the basis of the December official selling price. Any oil we sell in December will be priced on the basis of that. This effectively means we do have a two-month lag in our selling prices versus the sort of market spot price that we see. The current spot price we're seeing in November will form the basis for the Q1 for the January pricing in Q1 2022. Also here you can see how the average OSP for the third quarter and the fourth quarter. This is completely based on the average, or sorry, the official selling price on average. might not necessarily be reflected in the actual achieved price that Tethys receives, which we will look at in the next slide. Tethys Oil, we sell our oil on a monthly basis. We have a monthly lifting at the export terminal in just outside of Muscat. For each lifting, we use the monthly official selling price. Of course, the volumes are nominated proposed 2-3 months ahead of time. We are not aware of the pricing as that's done, then the pricing is set thereafter. There is no linkage between volume and pricing as such. It's rather based on expected production in conjunction with trying to balance out the over-underlift balance whereby we can only sell as much oil as we are entitled to. We will get back to the question of entitlement later. As you can see in the third quarter, our achieved price was $66.7 per barrel. This is a bit lower than the average OSP as you saw on the previous slide, but that is down to timing effect. Throughout this year, there has been some logistical issues and congestion at the export terminal, which means that we haven't been able to actually physically lift the oil within the month it has been nominated, which means that it has slipped into the following month, but still retained the pricing from when it was nominated. In Q3, for instance, we have in our accounts recorded the lifting for June, which normally would be part of Q2, July, August, which of course normally would be Q3. The September lifting was lifted early October and is thus recognized in Q4. Our achieved price is slipping by about a month. There's no real difference in pricing versus the average OSP. It's rather a question of slippage in time and a bit of waiting between the liftings. As you can see in the quarter, we sold 448,000 barrels, just a bit down versus Q2, but with a significantly higher price compensated when it comes to revenues, which brings us to the next slide. Revenue and the EBITDA, you can clearly see stepping up quarter by quarter since Q3 last year. This is very much driven, well, initially in part by production, but in recent quarters, particularly by the oil price while maintaining cost discipline in OpEx. We see a 13% increase in the revenue and other income, I think in Q3 versus Q2. We see EBITDA going up by 14% to $16.5. A clear progression very much driven by the flow-through of higher oil prices. Which brings us to the next slide and our operating expenditures, which have been maintained at a somewhat lower level than a few years back. We see a slight rise in this quarter from an exceptionally low level in Q2. It's up by 9% sequentially and $10 per barrel, just above $10 per barrel, OpEx per barrel. Admin costs are just above $2, which is in line with the historical level in general. This OpEx level, maintaining this OpEx level is ensuring that the increased top line is flowing through down to the bottom line. Now on to the subject of net entitlement, which has been much discussed recently. Just as a sort of extra clarification, just to ensure that everyone understands the mechanics behind it, which is not always clear when looking at our financial accounts. Tethys Oil's production comes from Blocks 3 and 4, which is a production sharing contract, which essentially means we get paid and we receive a portion of the oil produced as a contractor. It's split into two components. We receive cost oil to cover the cost incurred in production, and then we receive a portion of what remains, the profit oil, which is shared then with the government of Oman. Okay, what this means is first, a portion of the production is set off as an allowance for cost oil. This is typically somewhere in the portion of 30%-50%. In the case of three and four, it is fixed at a level between that. That is the maximum amount of production that can be set aside to cover cost in any given period. Anything that exceeds that cap is rolled forward and put into a cost pool. If the costs incurred are below that, well, then the lower amount is recovered. This means that the cost incurred in U.S. dollars is then converted to barrels of oil that we get to sell to cover that cost. That conversion is done at market price. What then remains is profit oil, and that is split between contractors and the government, where the government takes the majority share. It's important to remember that the cost oil is zero margin. While it makes up a big proportion of the oil we receive, it is purely to cover the costs incurred, and there's no margin on it. The value creation lies in the profit share and maximizing that over time. Moving forward. The net entitlement that Tethys receives is the combination of cost oil and profit oil barrels. As costs either decline or as a relative portion of the total value of production, the total volume of oil that we receive to sell may decline, and this has been the case in recent quarters, whereas we now are at 41% of production as our entitlement. However, this is in part due to the increased oil price. Given the costs incurred and the increased oil price, we need fewer barrels to recover that same cost. The amount of barrels going into cost oil while the value is intact becomes fewer. This means a higher proportion is available for profit oil, which is increasing with the oil price, as you can see in the graph to the right. While it's not so much about volume, it's about value, and this becomes most apparent in our free cash flow. While it might seem counterintuitive that we receive lower volumes and potentially slightly lower revenues than in the past, we are now making more profit from those same barrels. Case in point, moving forward, if we look at the cash flow for the year, we can see that we started the year with $55 million in the bank, and we have had free cash flow of $20 million. We've distributed $15.5 million, and yet we end this quarter on $59.4 million in the bank. Strong cash flow from what has been a year with what I would say decent, but also somewhat disappointing production and yet very strong cash generation, enough to cover our investments and the distribution. Moving on, one of the factors that can impact the cash flow between the quarters, just worth highlighting, is working capital. This recent quarter, we had a positive working capital effect, mainly driven by the receipt of funds from the EOG farmout. There were also some other counteracting factors, such as some delays in the receipt of funds from liftings. As you can see, this can swing quite a lot from quarter to quarter. While it's good to have a look at the year-to-date and big picture. Which brings us to free cash flow in the quarter, $13.1 million, $20 million in a year. Very strong cash generation throughout the year. Investment in the quarter, $9 million. We still have a full-year CapEx outlook of $47 million. That is adjusted for farm outs. As we've said in the past, we do expect CapEx to be ramping up towards the end of the year. We do expect higher CapEx in Q4 as a result. On that note, we end the financial section with a very strong balance sheet of $59 million in cash. We have solid oil and gas properties of $200 million. Very solid and even after the distribution of $15.5 million to our shareholders earlier this year. I hand it back to Magnus. Thank you very much, Petter. As you heard, we remain financially a very strong oil company. Turning to the operating part, let's go straight to a map of Oman and showing where we operate and where we invest and where we also derive our oil sales from. The Sultanate of Oman at the tip of the Arabian Peninsula, we have been active in Oman since 2006, and we currently have shares in five different licenses with Blocks 3 and 4 on the eastern part of Oman being our producing star performer. This is where we get our revenue from, this is where we get our free cash from, this is where we have... It provides our ability to distribute cash to shareholders and also invest in projects to find more oil and increase production. We do this in Block 3 and 4, but we also do it now in Block 49, 54, 58, sorry, and 56. Oman has been very good to us, and hopefully, we have been very good to Oman. We are certainly not the only oil company active in Oman. We have some of the majors and some of the major national companies and also some of our other smaller colleagues active in country. All in all, we are seeing a renaissance for the Omani oil industry with the return of several of the majors that were a bit reluctant in. Actually creating an opportunity for us to enter. Turning to the next slide, little bit of details. Blocks 3 and 4, we have a 30% stake. Originally, we had 50%. We farmed out to Mitsui of Japan in Japan in 2010, 2011. In effect, de-risking the entire appraisal and development phase of the then-known fields, Blocks 3 and 4. Block 49. We signed that block 100% in 2017. We farmed out to EOG of Houston, a really an expert in the entire reservoirs and unconventional production. In effect, we de-risked the first exploration phase that way by EOG offering to pay for the first well that we drilled in Block 49. 56, we actually farmed into an existing block, and we completed our farming campaign of 56 earlier this year, when we took over operatorship from Medco. We now hold 65% of Block 56 and are about to start an active and interesting exploration appraisal program for the upcoming year. Whereas Block 58 is our block for 100%. We signed it last summer. We've done all the preliminary work. We are quite encouraged about what we've seen, and we will start more seismic and then move on to drilling wells. At the moment, we have 100%. We are quite happy with having 100%. We will keep 100% through the seismic campaign, and then we'll see whether we will try to farm that out and get some interested partners in or if we will continue going at it alone. Blocks 3 and 4 remain our source of production and cash flow. The 2021 work program has been somewhat curtailed by the uncertainty regarding what would happen to oil prices in 2021, what would happen to our ability to produce in 2021, and of course, the general picture, what would happen to the world in 2021. As we approach the end of 2021, we can see that we have maintained cost control. We are a little bit under-invested when it comes to the production, and we would expect for next year to see an increase in capital expenditure on the block, primarily in the development side, but also as we continue to explore for more oil in 3 and 4. As you can see from this now rather familiar slide, the main pay fairway is the blue, light blue area where we have 3D seismic. We are adding 3D seismic in, or I should say interpreting 3D seismic in the dark blue area with area shots more recently. The Farha South field and the Shahd field are the main producing fields, both approaching some maturity. They are backed up by more recent discoveries, the Erfan field, for example, and some scattered exploration over the last three years. Exploration record this year is mixed. We found some oil, but not as much as we were used to from the past. On that note, we have seen exploration efforts step up. We will do more seismic, and in particular, we expect to see continued exploratory drilling, both in the near field area between, say, the Sawani field, the Erfan field, and the Shahd field, but also in the far field area, where we would be targeting some slightly larger structures in the south within the light blue area, but also both to the east and to the west. As we learn more about the potential of Blocks 3 and 4, we can still conclude that virtually every single well we have drilled has encountered some sort of oil, so a lot of oil has been generated here. Sometimes we have reservoir problems, sometimes we have excellent reservoirs. Sometimes there is a trap problem, sometimes we have excellent traps. The blocks are still very much alive, not only from a cash generating perspective, but also from an upside perspective. Turning to 49, we drilled a well here in first quarter, encountered large oil column, got no flows and concluded that there is oil there, but the reservoir is quite tight. We are lucky to have one of the world's best tight reservoir companies as partners, EOG Resources. Over the last 3-4 months, we had talks both with EOG, with our respective technical departments, and also with the ministry in Oman for the best way to take the Block 49 forward. We know there is oil there. We know there is reservoir. We also know that the reservoir is quite tight. We would expect to be able to present a clearer picture for what we're going to do with Block 49 in the near term, but we remain quite optimistic that 49 has created value and will continue to create value for us. Turning to 56, we have more activity upcoming. We will be focused primarily at the Al Jumd area, where we are going to do three wells with a combination of develop an appraisal well and exploration wells. The Al Jumd trend has more than 10 leads and prospects, and initially we are targeting some seven million barrels of prospective resources. In parallel with the drilling campaign in the Al Jumd area, we are also looking to do seismic in the central parts of Block 56. This will be a lot clearer in this picture. 56 covers really three potential play areas. We have Al Jumd, where we have ample 3D seismic, where we have discoveries, and where we are operating an extension of a producing field just to the left of this slide, to the northwest of the Al Jumd area, the Karim Small Fields. The drilling program we are putting in place for the next couple of months is to appraise the discoveries made within the Al Jumd trend in the block, and also drill at least one additional prospect within that trend to get a better picture of what is the actual, the full potential. The target of the program is to prove the commercial viability of the Al Jumd trend in Block 56, get long-term production test, and eventually get sustainable production from the prospects and the potential fields in that area. That's our first and primary target. Of course, we would be delighted to have a second production stream to complement what we see from Blocks 3 and 4. More exciting on the long-term value creation is what goes on in the central area. As you can see, we have a number of interesting leads generated from our interpretation of the 2D seismic, and we are focusing on doing an extensive 3D campaign in the south-central part of the block. We have a central fault running virtually in the middle of the block, which has created a lot of interesting traps, and we believe it's sourced from the Tertiary Basin, that is to the east of the central fault, with ample migration routes from that side. We hope to prove up a number of sizable drillable prospects through this seismic campaign. As Al Jumd hopefully moves into a production state, we will move the central area into a drillable prospect state. Probably the most exciting area that we are working with for the upcoming, shall we say, six months of our prospect portfolio. Turning to 58, it's a slightly different story. No known oil discoveries here, but known petroleum systems that work in other places in Oman. We are quite encouraged with what we see here, but the main target here is to get additional seismic. We turn quickly to the next. Again, leads identified. They stand up to the scrutiny we have conducted so far. Before we drill, we would like to have some 3D seismic to make sure that we drill in the right spot and that the trap integrity is confirmed. We would not expect any wells here until at the earliest, the latter part of 58, but we would hope to have confirmation that the leads hold as drillable prospects within the next six months. The Omani portfolio is evolving and increasing speed on the exploration side, supported by strong cash flows from blocks 3 and 4. Turning to the final slide. I'd like to remind you that we stand very strong financially. We generated a lot of cash in Q3. With increasing oil prices, we would expect to have a strong fourth quarter. Al Jumd should see some exciting drilling coming up, and 58, some interesting seismic. On that note, we will shortly turn to questions. I do hope that you will follow us closely as we move into one of the more work-prone quarters, fourth and fifth, and first quarter of 2021, while we maintain a strong cash flow from Blocks 3 and 4, but also, of course, not without risk. On that note, may I open the floor for questions, please? Ladies and gentlemen, if you wish to ask a question, please press zero one on your telephone keypad, and if you wish to withdraw your question, you may do so by pressing zero two to cancel. We already have a question from Stefan Fulga from Oxus Advisors. Please go ahead. Good morning, guys, and congratulations for the financials today. I've got some questions around production at Block 3 and 4. I was wondering, assuming that there would be no OPEC restriction, would the production in Q3 and Q4 be where it stands? In other words, I was trying to understand what has the most impact on the production level, whether it was the technical backlog of workover or whether there was still limitation associated to OPEC. As we move to next year on the same sort of question, assuming there would be no restriction on OPEC, where could you potentially see Block 3 and 4 returning to, and how should we think about CapEx to return to that level? Do you see, for instance, is 13,000 still something that you could see, the field production going back to without OPEC restriction? Thank you. Okay. Thank you, Stefan. Let's say that as the OPEC+ ceiling moves up, we would, I think it's fair to say we would not really expect to be too impacted by OPEC restrictions going forward. That said, the work program for 2021 was based on the potential of being restricted. Therefore, of course, we haven't really planned maybe to be able to produce all out. What we have noticed also is that as we put back wells on production, they need a bit of work to perform as well as they did when they were shut in. Thus the increase for additional workovers and the backlog we see on both development drilling and on workovers also based on the fact that it took slightly longer to get three rigs up and running than originally planned once the decision was taken to bring them on stream. I mean, it's all connected. The work program is based on expected production. If then expected production turns out to actually be higher than the work program was designed for, ramping up takes a bit of time. As we move into the fourth quarter, we are seeing the effects of those effects. Going forward, we will certainly be in a position to offer more guidance in the next couple of months as we also establish the budget for next year. I can certainly say that it would be our intention and the operator's intention and the JV's intention to go for a ramped up production for next year. As we get more data on what will be available and also on what work program will look like, we'll be able to get back to you and then offer more guidance there. Okay. Thank you. We have- Anything else? Yeah, sorry. Yes, we have another question from ABG. Please go ahead. Hi, guys. This is Karl-Erik Petersson from ABG Sundal Collier. I have a question regarding the drilling on Block 56. In terms of results, what are you looking for in order to classify this as a successful activity and what would be the timeline of announcements to the market? The most interesting part of the first well, the Al Jumd appraisal, it would be a horizontal section, and we would certainly like to see a sustained flow of, shall we say, sufficient flow to go for a long-term production and eventually a sustained production. We will be able to get back with more details as we approach the starting of the well. We are currently negotiating the rig. The rig has been identified. The rig is currently actually drilling for our partner, EOG, in their Block 36. We expect it to be released over the next couple of weeks, and we would expect to have more information on both the schedule and the drilling program during the course of December. We should certainly be able, barring any unforeseen delays or any drilling problems, to both guide as the work starts, but in particular, as we approach the end of the first quarter next year, we should be in a position to have a much clearer view of what we expect from Al Jumd over the next couple of years. No, the timeline really is more info as we move into the drilling sequence, and we should be in a position to evaluate the wells well before the end of the first quarter. Okay, thank you. We have another question from Stefan Fulga again. Please go ahead. Yes, I am. I'm back on this production and more for modeling purposes and CapEx. As we look forward, what do you think would be the level of CapEx required on Block 3 and 4 to maintain production flat? Is the current 32 or something the right number? Would it be a bit more? Yeah. I think, Stefan, I'd like to defer that question until we present the CapEx spending for next year. Okay. We should be in a position to discuss that in much more detail for our February call, when guidance and budgets for next year have been established. Okay. Thank you. It would be speculative at this stage, especially since we don't operate the block. Understood. Thanks. Ladies and gentlemen, another reminder, if you wish to ask a question, please press zero one on your telephone keypad. It seems that we have no further question. In that case, thank you for listening, and tune in again in three months time. Thank you. Ladies and gentlemen, this now concludes our conference call. Thank you all for participating. You may now disconnect.